Wells generally include a wellbore that extends within a subterranean formation, with the subterranean formation including a material that is to be produced by the well. As an example, a wellbore of a hydrocarbon well may extend within a subterranean formation that includes a hydrocarbon, such as a liquid hydrocarbon and/or a gaseous hydrocarbon, and the hydrocarbon well may be configured to produce the hydrocarbon from the subterranean formation.
There presently are a multitude of methods to determine physical properties of regions surrounding a wellbore. These methods generally are referred to as “formation evaluation” methods, and also may be referred to herein as “wellbore logging,” “well-to surface imaging,” and/or “cross-well imaging” methods depending on the location of sources and/or receivers utilized with the methods.
As an example, a number of methods may be employed to determine a distribution of electromagnetic properties, such as conductivity, resistivity, admittance, or impedance, in subterranean formations around a wellbore. These properties relate the current density passing through a region in the subterranean formation to the electric field applied to that region, and in general they depend on the frequency of the electromagnetic field. Conductivity generally refers to the ratio of the magnitude of current density to the magnitude of the electric field, and resistivity is the reciprocal of conductivity. Admittance is a complex number that incorporates both the ratio of the magnitudes, and the phase shift between, the current density and electric field as a function of frequency. Impedance is the reciprocal of admittance.
It is common to inject one or more injected materials into the wellbore and/or into the subterranean formation during construction of, during completion of, during stimulation of, and/or during production from the well. The extent to which these injected materials flow from the wellbore and/or penetrate into the subterranean formation may vary from well to well and/or within a given well and may be governed by a variety of factors. Examples of these factors include a porosity of the subterranean formation, a permeability of the subterranean formation, a chemical composition of fluids that are present within the subterranean formation, and/or a pressure utilized to inject the one or more materials into the subterranean formation.
From a practical perspective, it may be desirable to understand and/or quantify a location of these injected materials within the subterranean formation. One means to achieve this objective is to incorporate a “tracer material” into the injected materials that can alter a physical property of the region into which it is injected. Conventional detection methodologies, such as those described above, then may be utilized before, during, and/or after the injection to monitor changes in the corresponding physical property, such as electrical admittance, and subsequently to deduce the quantity and/or location of the tracer material. However, it often is difficult to generate sufficient contrast of the physical property between the injected materials and the subterranean formation to permit accurate detection of the injected materials within the subterranean formation utilizing conventional detection methodologies. Thus, there exists a need for improved methods of determining a spatial distribution of an injected tracer material within a subterranean formation.